High pressure gas-carbonated water miscible displacement process

ABSTRACT

Reservoir oil is produced by a quasi high pressure gas miscible solvent flood process. Immiscible carbonated water flow through the reservoir in essentially a single phase at an appropriate concentration and pressure leaves a widespread, fairly uniform distribution of carbonated residual oil which acts as a quasi solvent material. Subsequently, a fluid containing a gaseous phase is injected at a miscible pressure below the pressure at which the gas would have built miscibility with the reservoir oil prior to carbonation but high enough to possibly create by multiple contacts a zone miscible with the carbonated residual oil. The created miscible zone banks up the carbonated residual oil into a quasi miscible solvent flood bank. Preferably, the highest pressure exerted on the carbonated water will be equal to or greater than the miscible pressure of the gas, and the injection pressure of the gas will be at least 200 psi higher than highest injection pressure exerted on the carbonated water. An aqueous phase, part of which may be carbonated water, may be used with the miscible gas for mobility and other controls. In the process, the quasi solvent material is generated in place with the mobility and uniform sweep advantages of carbonated water, and the high pressure type of miscibility is created at a lower than normal pressure and banks up a carbonated oil solvent bank thereby providing some of the advantages of the miscible solvent flood process.

lea-13 P11 7912 XR United States Patent [191 Kern [ HIGH PRESSUREGAS-CARBONATED WATER MISCIBLE DISPLACEMENT PROCESS [75] Inventor: LoydR. Kern, lrving, Tex.

[73] Assignee: Atlantic Richfield Company, New

York, NY.

22 Filed: Jan. 22, 1973 [21] Appl.No.:325,381

3,084,743 4/1963 West et al. 166/274 X 3,096,821 7/1963 Dyes 166/2733,135,326 6/1964 Santee 166/273 X 3,138,204 6/l964 Richardson....166/273 X 3,227,210 l/1966 Trantham 166/273 X 3,342,256 9/1967 Bernardet al. 166/274 X 3,620,304 1 H1971 Hearn et al. 166/274 3,623,55211/1971 Vairogs 166/274 Primary ExaminerStephen .l. Novosad [57] 5ABSTRACT Reservoir oil is produced by a quasi high pressure gas Apr. 2,1974 miscible solvent flood process. lmmiscible carbonated water flowthrough the reservoir in essentially a single phase at an appropriateconcentration and pressure leaves a widespread, fairly uniformdistribution of carbonated residual oil which acts as a quasi solventmaterial. Subsequently, a fluid containing a gaseous phase is injectedat a miscible pressure below the pressure at which the gas would havebuilt miscibility with the reservoir oil prior to carbonation but highenough to possibly create by multiple contacts a zone miscible with thecarbonated residual oil. The created miscible zone banks up thecarbonated residual oil into a quasi miscible solvent flood bank.Preferably, the highest pressure exerted on the carbonated water will beequal to or greater than the miscible pressure of the gas, and theinjection pressure of the gas will be at least 200 psi higher thanhighest injection pressure exerted on the carbonated water. An aqueousphase, part of which may be carbonated water, may be used with themiscible gas for mobility and other controls. In the process, the quasisolvent material is generated in place with the mobility and uniformsweep advantages of carbonated water, and the high pressure type ofmiscibility is created at a lower than normal pressure and banks up acarbonated oil solvent bank thereby providing some of the advantages ofthe miscible solvent flood process.

24 Claims, No Drawings HIGH PRESSURE GAS-CARBONATED WATER MISCIBLEDISPLACEMENT PROCESS BACKGROUND OF THE INVENTION This invention relatesto a displacing process for recovering oil from a subterraneanreservoir. More specifically, a high pressure gas type of miscibledisplacing process and carbonated water are combined to generate a quasihigh pressure gas-miscible slug process retaining some of the advantagesand overcoming some of the disadvantages of both a high pressure gasprocess and a solvent slug process.

The production of oil is enhanced by various displacement techniqueswhich are generally classified as miscible and immiscible and which maybe conducted at any time during an oil recovery program. In thesedisplacement techniques, the force of an injected fluid propels oilwithin the formation toward at producing well or horizon. One type ofimmiscible displacement process involves flooding the reservoir withcarbonated water. Three types of miscible displacements are the solventor miscible slug or flood process, the enriched gas or condensing gasprocess, and the high pressure gas process.

Water drive or waterflooding is the most widely used displacementtechnique. It has been proposed to use carbonated water instead ofwater. The carbonated water process is classified as an immiscibledisplacement process, and oil recovery depends on the energy of thewater with some increase in oil recovery due to oil swelling caused bytransfer of carbon dioxide from the carbonated water to the oil. It isgenerally assumed that recovery obtainable with the use of water orcarbonated water is limited and much of the oil originally contained inthe reservoir is left in the reservoir. The oil left in the reservoir isresidual to the type ofimmiscible flood process.

In order to increase oil recovery above that which is obtained byimmiscible processes in some reservoirs, a variety of miscible recoveryprocesses have been disclosed. It is possible for miscible fluidsto.displace substantially all of the oil from the part of the reservoirswept or contacted by the miscible fluid. In general, these processesmay be considered as a variation of either the enriched or condensinggas process, the solvent flood process, or the high pressure gasprocess.

In the miscible flood process, a bank or slug of solvent fluid isinjected at a pressure, for example, 1000 psi and greater, such that atreservoir conditions the slug material will either be miscible uponfirst contact or will quicklydevelop a miscible-like zone with the inplace oil. In this technique, the solvent is injected as a relativelynarrow transitional displacing phase between oil and a drive fluid.Solvents include hydrocarbon types, for example, propane and butane,nonhydrocarbon types, for example, carbon dioxide, and mixtures orsolutions thereof. Other materials may be employed to provide acombination slug. Water and other additives have also been. combined oralternately injected with a solvent-like material to partially influenceunit displacement of the slug of solvent. When the solvent is mixed withwater, the process is still a miscible flood process in that the solventacts as a distinct phase of the mixture. The relatively narrow band ofsolvent is displaced by such fluids as water, miscible and immiscible.gases and mixtures thereof. In addition to economic factors, there areserious problems involved in the miscible slug process. Unless anexpensively large solvent slug is used, it is difficult to form andmaintain a uniform flood front of sufficient thickness and breadth toprevent loss of depletion of the band or bank of solvent. If the solventband is broken or depleted, miscibility is lost, and an immiscible driveresults and'cannot be reestablished unless an additional solvent band isinjected.

A high pressure gas process uses a highly volatile gaseous materialwhich is less soluble in oil or requires a higher pressure to developmiscibility than the solvents used in miscible flood processes. In thehigh pressure gas process, a gas, for example, methane or flue gas, isinjected at a pressure at which the gas will build or create miscibilitywith the oil by multiple contacts. The gas contacts oil and is enriched.The enriched gas, being less viscous than the oil and not yet misciblewith it, moves forward more rapidly than the oil just contacted intocontact with fresh oil to be further enriched. This enriching ormultiple contact process continues until a miscible transition zone isformed between the oil and the injected gas. The leading edge of thiszone is substantially miscible with the oil except possibly for somerelatively small precipitated heavy oil phase. The trailing edge of thezone is miscible with the injected gas. Inside the zone, all contiguousfluids are miscible at their leading and trailing edges. In many cases,the high pressure gas mechanism requires a pressure greater than thereservoir will withstand. This may be caused by the properties of thereservoir oil or by the nature of the formation. In addition, it isoften impractical or undesirably costly to obtain and maintain thesehigh pressures. In many reservoirs, these high pressures-also adverselyaffect sweep efficiency.

In any displacing process, depending on the reservoir, one or moreproblems may result from such factors as gravity segregation, viscousfingering, reservoir stratification and the like. In horizontal(nonvertical) displacements, such factors affect both the horizontal(areal sweep) and vertical sweep. These factors especially influence themiscible slug process. and the high pressure gas process. It is standardpractice to employ laboratory testing and reservoir data to establishand start a recovery program. The recovery program may later be modifiedto overcome problems as they arise without departing from the originalconcepts of the recovery program. Tests concerning high pressure gasdisplacements are frequently subject to uncertainties especially as tothe minimum pressure required to create a miscible zone and to problemsinvolving deasphalting or leaving some high molecular weight componentsin the test core.

it would be desirable to provide a frugal, timely, and reliable recoveryprocess with improved sweep efficiency and which is conducted at apressure lower than required for a high pressure gas miscible processusing the same relatively inexpensive high pressure gas displacingmaterial and which permits use of less solventlike material and is lesscritical or has greater tolerance than the process would otherwise have.

SUMMARY OF THE INVENTION A high pressure gas type of miscible displacingprocess and carbonated water in essentially a single phase are combinedto generate a quasi high pressure gasmiscible flood process wherein themiscible solvent is carbonated oil. A carbonated water solution isforced through the reservoir to contact oil under conditions such that asubstantial amount of carbonated oil is left in the area swept by thecarbonated water. The high sweep efficiency of the carbonated water andthe amount of carbonated water are such that a reasonably uniformwidespread zone of this carbonated residual oil is created. Thereafter,a fluid containing a gaseous phase is injected under conditions suchthat the gaseous phase is able to bank up a zone of carbonated oil aheadof it and miscibly sweep a portion of the reservoir at a pressure lowerthan the pressure at which the gaseous phase is miscible with theoriginal reservoir oil. The carbonated oil bank thereby acts like aquasi miscible solvent slug and allows the displacement process to beconducted at the lower pressure.

This displacing process has the advantages of miscible displacement notfound in immiscible processes, such as water-flooding, low pressure gasand carbonated waterflooding. This process enables use of the highpressure gas mechanism at a lower pressure than when the same type ofhigh pressure gas type of displacing material is used and permits use ofless carbon dioxide than is normally used in a miscible flood processusing carbon dioxide as the solvent. The size of the quasi solventcarbonated oil bank and uniform spread or placement of the carbonatedoil are improved while providing for better control of such factors asgravity segregation. viscous fingering, reservoir stratification andsweep efficiency. The process is especially advantageous for tertiaryrecovery of oil, for example, oil left in a reservoir after thereservoir has been swept with water. The process of this invention isalso especially advantageous for lower pressure reservoirs. Suchreservoirs are frequently at a pressure much lower than the pressure atwhich a miscible high pressure gas process is conducted, and it isnecessary to repressure the reservoir before initiating the miscible gasprocess. Repressurization with a gas is frequently time consuming andimpractical. Repressurization with water has been frequently suggested;however, repressuring with water is time consuming and may beinefficient or too costly. in this invention, carbonated water could beused both for repressurization and for the other objectives of this invention, thereby accomplishing dual results and increasing processefficiency.

The process of this invention also provides a frugal use of carbondioxide. For example, it is generally believed that a set amount ofcarbon dioxide dissolved in water to provide a carbonated waterfloodprocess will provide much less oil recovery than the same amountofcarbon dioxide used as a solvent band in a carbon dioxide mixcibleflood process. But when the carbonated water is used in a manner hereinprovided in combination with a modified high pressure gas mechanism, alesser amount of carbon dioxide can provide the same or a greater amountof oil recovery than a greater amount of carbon dioxide when used in acarbon dioxide miscible flood process.

DETAILED DESCRIPTION OF THE INVENTION The method of this inventioninvolves a multiple stage process to recover oil from a subterraneanreservoir wherein there'fis at least one injection point and oneproduction point which are spaced apart one from the other. Access tothe injection and producing points will be through wellbores, and thepoints may be r 4 spaced laterally, vertically, or diagonally from eachother in any pattern or multiple pattern and on any appropriate spacing.

One stage of the method'centers on in situ generation of a quasi solventmaterial comprised of residual carbonated oil which is formed bytransfer of carbon dioxide from carbonated water into a residual oilphase and by subsequent injection of a fiuid containing a gaseous phasewhich at an appropriate pressure collects and banks up the carbonatedresidual oil phase. The carbonated residual oilphase is generated insitu in a manner which improves sweep and uniform distribution of thesolvent-like carbonated oil material by injecting into at least oneinjection point water and carbon dioxide in a ratio, at a bottomholepressure, and in a manner such.that a carbonated water solution isforced through at least a portion of the reservoir between the injectionand producing points for the primary purpose of immiscibly sweeping thereservoir, contacting and bypassing oil in the reservoir, and leaving inthe swept portion of the reservoir a quasi solvent zone of residual oilwhich is greatly enriched in carbon dioxide. As a secondary purpose, thecarbonated water may be used to raise the pressure of the reservoir to adesired pressure for increasing the concentration of carbon dioxide inthe carbonated residual oil phase and for carrying out the remainder ofthe process. The concentration of carbon dioxide in the oil phaseresidual to immiscible passage of carbonated water is primarilydependent upon the concentration of carbon dioxide in the carbonatedwater solution, the amount of residual oil in the area the carbonatedwater solution, the pressure of the carbonated water solution, and untilequilibrium is reached or the residual oil is saturated with carbondioxide, the volume of carbonated water solution injected at a givencarbon dioxide concentration. 0f course, as long as the sweep pattern isexpanding, some residual oil at the fringe of the sweep pattern willnever be saturated.

Widespread uniform placement of the quasi solvent material or carbonatedresidual oil enhances the displacement efficiency of a gaseous phaseinjected after the carbonated water and lowers the pressure at which thegaseous phase may miscibly displace oil in the reservoir. The gas inthis gaseous phase is characterized by the'fact that it is capable atthe reservoir temperature of creating at a first miscible pressure azone substantially miscible with the reservoir oil except possibly somerelatively small separated or precipitated phase of the oil. Thepressure at which a gas will build miscibility with an oil by multiplecontacts as previously mentioned is subject to experimental variation.Therefore, as used herein, this first miscible pressure is the lowest,reasonably certain pressure at which the gas will build miscibility withthe reservoir oil at the reservoir temperature. The gas in the gaseousphase is also capable of creating by multiple contacts at a secondpressure. a zone substantially miscible as earlier described with atleast a major part of the carbonated residual oil solution. As hereinpointed out; the concentration of carbon dioxide in the carbonated oilsolution may vary depending on equilibrium or undersaturated conditionsbetween the residual oil and the carbonated water in the reservoir. Thesecond miscible pressure at which the gas will build miscibility withthe carbonated oil solution at the reservoir temperature depends in parton the carbon dioxide concentration in the carbonated oil solution andis also subject to the experimental variations mentioned. Therefore, asused herein, the second miscible pressure is the lowest reasonablycertain pressure at which the gas will build miscibility with reservoiroil saturated with the maximum concentration of carbon dioxide in thecarbonated oil solution that could reasonably be achieved at equilibriumconditions between the reservoir oil and a carbonated water solution ata reservoir pressure used in the process. For this purpose the ratio ofcarbon dioxide to water in the carbonated water solution will be themaximum value determined from the injection history and will usually behighest shortly before commencement of injection of the gaseous phasesince it is desirable for the carbonated residual oil to be richest atthis time, and the pressure and concentration of carbon dioxide in thecarbonated water will, therefore, be highest at this time. It isparticularly important to note that it is essential in this process thatthe second miscible pressure at which the gas will create miscibilitywith carbonated oil solution be less than the first miscible pressure atwhich the gas will create miscibility with the reservoir oil. The gas inthe gaseous phase, which may or may not contain some carbon dioxide,will be natural gas or a methane rich gas, flue gas, a nitrogen richgas, ethane, or some other similar inert gas or mixture of gases, andthe richness of the gaseous phase may be adjusted in known ways toenhance development or maintenance of miscibility.

The advantages and objectives of this invention are also accomplishedonly if at some time during the displacement process the bottomholeinjection pressure of the gaseous phase is at least as great as thesecond miscible pressure and only if during the displacement process thebottomhole injection pressure of the gaseous phase stays below the firstmiscible pressure. The injection pressure of the gaseous phase will alsobe below. the overburden pressure of the reservoir. Preferably, thebottomhole injection pressure of the gaseous phase will also eventuallybe at least 200 psi and greater above the bubble point of the residualcarbonated oil at reservoir conditions or above the final or highestinjection pressure exerted on the carbonated water. At these pressures,the fluid containing the gaseous phase banks up carbonated residual oilas a quasi miscible solvent slug to provide the advantages of a miscibleslug process. The quasi solvent slug of carbonated residual oil isgathered and banked up by the fluid containing the gaseous phase at apressure lower than the pressure at which the gas in the gaseous phasewould build miscibility with the reservoir oil by itself.

As previously indicated, there are several interrelated aspects of theprocess which prescribed conditions for the carbonated water solutionand the subsequent gaseous displacing medium. Briefly it has beenindicated that a carbonated residual oil phase must be left afterpassage of the carbonated water and the distribution of this carbonatedresidual oil phase should be reasonably uniform and widespread. Theamount of carbonated residual oil phase should be such that subsequentinjection of a gaseous phase can initially build the carbonated residualoil into a quasi solvent-like slug, or bank within a reasonable distanceof the injection point and can rebuild the slug bank when and if some ofthe quasi solvent bank between the gaseous phase and oil is lost. Theconcentration of carbon dioxide in the residual oil phase should be highenough to allow the gaseous phase to develop a zone miscible with thecarbonated oil at a reasonable pressure by the high pressure gasmultiple contact method previously described. The miscible zone thenbanks up carbonated residual as it moves through the formation.

As stated, the distribution of the quasi solvent carbonated residual oilshould be generated in a reasonably uniform and widespread manner withimproved sweep. The significance of this on the process can best beunderstood by considering the factors which control sweep. Two factorscontrolling injection sweep out pattern are variations in permeabilityincluding the presence of porous and tight streaks in the reservoir andthe geometry of the fraction of the reservoir contacted by an invadingfluid. Even if the reservoir were perfectly homogeneous, the fluid flowwould streamline toward the producing point and not sweep the totalreservoir. For both factors, the sweep out efficiency is primarilycontrolled by differences in gravity and mobility between the injectedfluid and the reservoir fluid. Gravity differences tend to cause gravityoverride especially when verticle permeability is present. Differencesin mobility between the driving fluid and the displaced fluid tend tocause fingering and the geometry of the sweep pattern to streamlinequicker and to cause the displacing fluid to break into the producingpoint. Differences in mobility also increase the tendency of gravitydifferences to cause the lighter fluid to override. Mobility differencesare usually expressed in terms of mobility ratios which are found bydividing the mobility of the drive fluid behind a sweep front by themobility of the displaced fluid ahead of the front. Mobility is broadlydefined as the permeability divided by the viscosity. When the mobilityratio is large, a relativeiy in efficient sweep occurs A displacingfluid with a mobility of between 0 and 1 times the mobility of thedisplaced fluid provides a high sweep efficiency. Carbonated water withno significant amount of gaseous carbon dioxide usually provides amobility ratio of about one and provides a good sweep out pattern. Incontrast, a miscible slug process using carbon dioxide gas would have amobility usually at least ten times that of carbonated water and thesweep out is less. In this method, the quasi solvent carbonated residualoil is to be generated in situ with the high sweep out efficiency ofcarbonated water flooding so that the quasi solvent is generated in situin a more widespread reasonably homogeneous or uniform manner throughoutthe pay zone unless stratification is very severe. This requirementthereby places a restriction on the pressure or the ratio of water tocarbon dioxide. As illustrated, a significant free gas carbon dioxidephase would adversely affect the sweep efficiency and uniform placementof the quasi solvent. Consequently, at the-anticipated sweep pressure,the amount of carbon dioxide should not exceed the amount that the watercan hold in solution. Stated in another way, the ratio of water tocarbon dioxide in the solution should be at least as great as the ratioof water to carbon dioxide in a saturated'carbonated water solution atthe bottomhole pressure at which the water and carbon dioxide areinjected into the injection point and at the temperature of thereservoir. This is the rnaximum saturation pressure since there is apressure drop in the reservoir. Transfer of carbon dioxide from thecarbonated water solution to the residual oil will tend to offset thepressure drop until the oil becomes saturated at equilibrium conditionswith the carbonated water. When saturation of the residual oil isanticipated, a mean reservoir pressure instead of the bottomholeinjection pressure is selected for the maximum saturation pressure forthe ratio of water to carbon dioxide to avoid formation of a free carbondioxide gas phase.

As stated, it is also necessary that carbonated residual oil be left inthe reservoir after passage of the carbonated water solution. Thisrequirement places the same sort of restrictions on the ratio of waterto carbon dioxide as just described. A substantial free carbon dioxidephase would tend to deplete or sweep the residual oil from the displacedarea because as previously mentioned, pure carbon dioxide is considereda solvent slug material. Moreover, as will be pointed out, the pressureduring the carbonated water injection state of this recovery method willusually be either raised to a pressure or will be at a pressure abovethe pressure at which pure carbon dioxide would be miscible with thereservoir oil. At this pressure, a free carbon dioxide phase wouldmiscibly sweep the oil from the invaded region; consequently, injectionof the water and carbon dioxide will be conducted in a manner and underconditions such that a substantial slug-like amount of free carbondioxide does not develop in the region where the quasi solvent materialis to be generated and does not remove the residual or bypassed oil inthis region. As mentioned, it is also desirable to avoid formation of afree carbon dioxide phase for other reasons. For example, channelling orgravity segregation could occur when generating the quasi solvent slugof carbonated residual oil. This would tend to cause less contact of theoil and less carbon dioxide from being transferred to and dissolved inthe residual oil. The injection conditions and ratio of watei to carbondioxide are, therefore, such that a substantially stable carbonatedwater solution at the temperature and pressures encountered is formedand such that, if any carbon dioxide is not dissolved or comes out ofsolution, the undissolved carbon dioxide will not interfere with themechanism of the process described herein. When injecting the carbondioxide and water, the appropriate ratio is selected in accordance withsuch principles and the purposes of this process.

In addition to the aforementioned need for generating and leaving enoughcarbonated residual oil to act as a quasi solvent slug, it has beenshown that a widespread area of carbonated residual oil is desired andthat the desired concentration of carbon dioxide in the carbonatedresidual oil is to some extent based on the type of gaseous phasesubsequently injected and the desired reduction in multiple contactmiscible pressure to be achieved by the process. These requirements anddesires are. along with other things, dependent on the amount ofcarbonated water solution injected and the solution pressure.

The amount of carbon dioxide and water introduced into the injectionpoint is such that when the carbon dioxide and water are in solution,the solution generates in situ enough carbonated residual oil solutionto main tain miscibility with the subsequently injected gaseous phasethroughout a significant portion of reservoir. The quantity of solutionto be injected may be calculated and determined by known design and testprocedures under simulated conditions. The optimum amount for anyparticular reservoir application will, of course, be dependent on manyvariables and allowances. Much has been published on reservoirdisplacement calculation and design techniques. The amount will beeffected by geometry, reservoir temperature, reservoir pressure whichwill usually be increased during the pro cess, reservoir properties andreservoir fluid properties, the solubility of carbon dioxide in waterthepressures and temperature in the reservoir, rate of injection, theproperties of the following gaseous phase, the degree of miscibilitypressure decrease desired, the amount of oil left in place at the startof the process and left residual to passage of the carbonated water,sweep efficiency, allowances for fingering, length effects, dispersion,dilution and diffusion, mass transfer rates, equilibrium coefficients,phase behavior, and the like. From a consideration of such factors,experience with miscible slug processes, experiments with the process ofthis invention, and the primary objective of the carbonated solutionwhich is to transfer, preferably at saturated equilibrium conditionsbetween the carbonated water and reservoir oil, carbon dioxide to theresidual oil over a large area so that the carbonated residual oil maybe miscibly displaced at a lower than normal pressure by a gaseous phasewhich builds miscibility by multiple contacts between the gaseous phaseand the carbonated residual oil, depending on sweep efficiency, theminimum amount of carbonated water solution injected into the reservoirshould be at least as great as 10 to 30 percent and more of the porevolume of the reservoir within which the process is practiced.

As previously indicated, the pressure exerted on the carbonated watersolution is selected from several viewpoints. The pressure is chosen toavoid formation of a substantial free carbon dioxide phase whengenerating the quasi solvent material. The injection pressure affectsthe injection rate which in turn affects the rate at which the reservoirpressure rises, the linear rate of flow of carbonated water in thereservoir, and to some extent the amount of carbonated water solutionneeded since mass transfer of carbon dioxide into the residual oil is atime dependent process. The longer the flow path or the lower thedisplacing velocity, the longer is the time for mass transfer. Thepressure also affects the rate of mass transfer and the amount of carbondioxide that can be dissolved in the carbonated water solution. Aspreviously mentioned, the carbon dioxide transfers to bypassed residualoil until equilibrium is reached.

During early stages of the process, injection and res-- ervoirconditions can vary widely between reservoirs and situations. But once agiven system and in situ generation of the quasi slug material is fromradial and pressure standpoints well underway, the injection ratio ofcarbon dioxide to water will normally not exceed water saturationconditions. Much has been published on the solubility of carbon dioxidein water which increases with increasing pressure. For temperatures upto 2l0F and pressure below 400 atmosphere or 5800 psi, the solubility ofcarbon dioxide in water decreases with increasing temperature. Ingeneral, the solubility of carbon dioxide in water decreases with anincrease in salt content in the water. In general, therefore, the amountof carbon dioxide which can be dissolved in water is dependent on thetemperature of the reservoir, the purity of the water, and the partialpressure of the carbon dioxide. The temperture is fixed by thetemperature of reservoir in the region where the quasi solvent slug isto be generated. The pressure is determined by the pressure of. thereservoir, the injection rate and pressure, and a time dependent meanspressure in the region where the quasi solvent carbonated residual oilis generated. The water, which is preferably deoxidized, will usually beof the type available inshallow formations near or in the field of thereservoir and will usually be a brine solution. Adjuvants, which willaid the process, could be added. For example, anionic, cationic,nonionic, hydrophilic, or lyophilic surface active agents,viscosity-increasing agents, emulsifiers, and the like, may be addedinitially or at any stage of the displacement method. In general, thevolumetric ratio of water to carbon dioxide at standard conditions ofpressure and temperature is at least as great as l to 33 and equal to orless than I to 6.

In addition to the aforementioned pressure considerations, the finalpressure exerted on the carbonated water affects the initial injectionpressure for the fluid containing the miscible gaseous phase. It ishighly desirable that before the miscible gaseous phase is injected, thebottomhole pressure at the injection point be at least as great as thesecond miscible pressure previously defined, that is, the pressure atwhich gas in the gaseous phase will create miscibility with thecarbonated residual oil. This pressure level is desired for manyreasons, most of which have been previously indicated. There is aminimum pressure at which the gas will develop a miscible zone bymultiple contacts with the residual carbonated oil. This minimumpressure depends in part on the concentration of carbon dioxide in theresidual oil and as previously explained increasing the pressure exertedon the carbonated water increases mass transfer of the carbon dioxide tothe residual oil and can increase the equilibrium concentration ofcarbon dioxide in the residual oil. Until this minimum pressure isreached, the fluid containing the gaseous phase will immiscibly sweepthe reservoir bypassing residual carbonated oil and creating thecollateral effects usually involved in immiscible displacements. Optimumsweep or eventual recovery is obtained if the gaseous phase quicklybuilds the miscible zone and banks up the quasi solvent slug ofcarbonated residual oil.

Generally, for the carbonated water phase of the process, a meanreservoir pressure is selected and a carbon dioxide solution is injectedor created at an appropriate bottomhole injection pressure above themean reservoir pressure either by injection a carbonated water solutionor by injection water and carbon dioxide separately into a well bore ina manner such that the necessary mixing and dissolving of the carbondioxide in the water will occur in the well bore and/or in the reservoiradjacent to the injection well. This latter procedure contemplates theinjection of precalculated portions of chilled or unchilled carbondioxide and water or undersaturated carbonated water to form the desiredcarbonated water solution. The carbon dioxide may be liquid, gaseous, ora dense fluid above its critical temperature. The carbon dioxide may beobtained by combustion of methane or other fuel and all or a portion ofthe carbonated water solution formed above ground by using water toabsorb carbon dioxide from the products of combustion. The separatednitrogen could be injected into another area of the field as part of themiscible gaseous fluid. A premixed chilled solution of carbon diox idein water may also be injected. When carbon dioxide is produced, it maybe recycled for reuse in the reservoir or some other reservoir.

As previously indicated, the reservoir process may be carried out in anysuitable reservoir whether previously depleted or not and previouslywater flooded or not, but will usually not be conducted in a reservoirin which a miscible displacement was previously conducted unless forsome reason the miscible displacement was grossly unsuccessful and asubstantial residual oil saturation is present. Generally, however, theprocess will be conducted in a depleted reservoir which has beendepleted either by natural or artifical means and may be after waterflooding. in such a reservoir, there may be a gas phase and thereservoir liquid is usually at a relatively low saturation pressure. Insuch situations, the oil-bearing formation or reservoir from which oilis to be displaced will first be brought to predetermined conditions.For example, the static pressure at the injection should be at 400 psibefore commencement of carbon dioxide-water injection and preferably atleast 1000 psi. If the reservoir is not at the desired pressure, thereservoir may easily be brought to desired pressure by fluid injectionor water injection. After the reservoir pressure has been raised to thedesired pressure, the process may be commenced. Some reservoirs maycontain an undesirable amount of methane or the like at a high pressure,and it may probably be more desirable to first produce this formationlowering the methane pressure and the amount of methane dissolved in thecrude oil. After the reservoir has been depressured and the methaneallowed to escape from the oil, the oil invention may be conductedwithout repressurization. It may also be desirable to first treat, inways known to the art, the formation with materials that balance thepermeabilities of strata in the reservoir or that reduce the effect ofreservoir inhomogenieties.

As already shown, after injection of the carbon dioxide and water, afluid containing a gaseous phase is injected in an amount sufficient toprovide a fluid drive miscible with the quasi solvent carbonatedresidual oil solvent. Usually, the amount of gaseous phase injected isat least 20 percent or more of the reservoir pore volume. Frequently,the gaseous phase is injected until reakthrough or an excessive gas-oilratio riseat the production point or points. The actual quantity of gasadded to the reservoir will be dependent upon the reservoir and whetheror not the miscible gaseous phase is mixed with a liquid such as water.Preferably, at least a portion of the fluid including the gaseous phasewill also include an aqueous phase. Injection of water with I themiscible gaseous phase, either intermittently or simultaneously to causea two-phase flow in the reservoir, provides improved results inreservoirs where control of gravity and mobility factors is essential.The reservoir volumetric ratio of water to gaseous phase will rangebetween 10 partswater to 1 part gas and 1 part water to 10 parts gaswith the usual range between 1 to 4 and 4 to 1. This ratio is dependenton reservoir characteristics and process conditions as is designed tocause the gaseous phase and aqueous phase to flow at equal rates, or tocause the gaseous phase to flow slightly faster than the water, or tocause the two to flow at rates such that a preceding miscible gas slugor slugs is not depleted. US. Pat. No. 3,096,821 mentions the principlesinvolved.

It is particularly advantageous and useful in this pro. cess to make thefirst part of the aqueous phase carbonated water. As previously noted,the gaseous phasebuilds miscibility with carbonated residual oilsolution. In other words. the fluid containing the gaseous phase isinitially immiscible with carbonated oil. If noncarbonated water wereinjected with the gaseous phase, transfer of carbon dioxide to theinjected water might in some situations prolong the distance before themiscible zone is formed. Use of a carbonated aqueous phase also suppliesadditional carbon dioxide transfer to the oil as the sweep patternexpands or if miscibility needs to be reestablished. It is usuallyunnecessary to use carbonated water throughout injection of the gaseousphase. The injected water will bank up water already in the reservoir.Therefore, as a practical matter, the carbonated portion of the aqueousphase will usually be less than percent of the reservoir pore volume.

Preferably, throughout at least the latter part of the carbonated waterphase and at least the first half of the fluid injection phase of theprocess, the pressure exerted on the carbonated water and gaseous phasewill be maintained or increased. During the carbonated water phase, thisprevents substantial vaporization of carbon dioxide from the carbonatedwater and residual oil. and during the gaseous injection phase, thiseither builds and maintains or simply maintains miscibility between thegaseous phase and the quasi solvent carbonated residual oil. For variousreasons, production rates and other factors prevent maintenance or" thedesired pressure throughout the reservoir. The method of this inventionstill provides for improved recovery and for recreation of miscibilitywhen the pressure can be restored.

As the process is carried out, oil is produced from the reservoirthrough one or more production wells arranged in a pattern depending onthe reservoir characteristics and operating systems. Production may beshut in or retarded when desired.

The process is readily adaptable to any reservoir at any stage ofdepletion containing oil suitable for dissolving carbon dioxide andbuilding miscibility with a gaseous phase at a reasonable pressure belowthe overburden pressure. The process is most readily applied on afield-wide basis wherein the reservoir is traversed by several wellbores. The wells may be arranged in a conventional manner such as anopen or closed five spot, seven spot, or line pattern, or as theindividual situation demands, with certain of the well being used forinjection of the displacement media and others for production or" thehydrocarbons.

Example A synthetic Boise Core initially saturated with oil from WassonField, West Texas was subjected to injection of 6 pore volumes ofcarbonated water which was slightly undersaturated at 2000 psig and l09Funtil oil production had nearly ceased and the producing carbonatedwater contained at least 93 percent of the injected carbon dioxideconcentration. The carbonated water contained 4.5 pounds of carbondioxide per 100 pounds of water. During carbon dioxide injection, thecomposition of the effluent water was monitored. Initially, the carbondioxide concentration in the effluent water was low, indicating transferof carbon dioxide from the carbonated water to be residual oil. Aftercarbonated water flooding, the core was subjected to methane injectionat the same conditions, and 27 percent by volume of the oil residual tocarbonated water flooding was produced. Swelling of oil could notaccount for the increased oil production because in previous Boise Coreexperiments, it had been shown that methane injection at double thisinjection pressure would only produce 5 percent of oil residual to waterflooding. The swelling of oil by methane at 4000 psig is the same asswelling by carbon dioxide at 2000 psig. The carbonated water-methanedisplacement, therefore, significantly increased residual oilproduction. In other Boise Core experiments, it had been determined thatthe miscible pressure between carbon dioxide and Wasson oil at 109F wasbetween 1350 and 1500 psig, and that the miscible pressure betweenmethane and Wasson oil at 109F was estimated to be above 5000 psig. Thisexperiment and others indicate that Wasson oil having a composition likethat produced by carbonation as described above will be substantiallymiscible with methane at pressures around 2000 psig.

Reasonable variations and modifications are practical within the scopeof this disclosure without departing from the spirit and scope of theclaims of this invention.

The embodiments of the invention in which an exclusive property orprivilege is claimed are defined as follows:

1. A method of recovering oil from a subterranean reservoir whereinthere is at least one injection point and one production point, saidpoints being spaced one from the other, which method comprises:

a. injecting water and carbon dioxide into said injection point at abottomhole pressure sufficient to force a carbonated water solutionthrough at least a portion of said reservoir between said injection andsaid production points and to form a zone of carbonated oil solution insaid portion of said reservoir, the ratio of water to carbon dioxidebeing at least as great as the ratio of water to carbon dioxide in asaturated carbonated water solution at said bottomhole pressure and atthe temperature of said reservoir; b. thereafter injecting a fluidincluding a gaseous phase into said injection point, the gas in saidgaseous phase being capable at the said reservoir temperature ofcreating at a first miscible pressure a zone substantially miscible withsaid reservoir .oil and of creating at a second miscible pressure, azone substantially miscible with at least a part of said carbonated oilsolution, said second miscible pressure being less than said firstmiscible pressure, said gaseous phase being injected at a bottomholepressure below said first miscible pressure and at least a portion ofsaid gaseous phase being injected at a bottomhole pressure greater thansaid second miscible pressure; and producing oil from said reservoirfrom said production point.

2. The method of claim 1 wherein the fluid including a gaseous phasealso includes an aqueous phase.

3. The method of claim 2 wherein the aqueous phase is a carbonated watersolution.

4. The method of claim 1 wherein before the fluid including the gaseousphase is injected, the bottomhole pressure at the injection point is atleast as great as the second miscible pressure.

5. The method of claim4 wherein the fluid including a gaseous phase alsoincludes an aqueous phase.

6. The method of claim wherein the aqueous phase is a carbonated watersolution.

7. The method of claim 4 wherein at least a portion of the gaseous phaseis injected at a bottomhole pressure at least 200 psi higher than thehighest bottomhole pressure reached during step (a) at said injectionpoint.

8. The method of claim 7 wherein the fluid including a gaseous phasealso includes an aqueous phase.

9. The method of claim 8 wherein the aqueous phase is a carbonated watersolution.

10. The method of claim 1 wherein at least a portion of the gaseousphase is injected at a bottomhole pressure at least 200 psi higher thanthe highest bottomhole pressure reached during step (a) at saidinjection point.

11. The method of claim 10 wherein the fluid including a gaseous phasealso includes an aqueous phase.

12. The method of claim 11 wherein the aqueous phase is a carbonatedwater solution.

13. The method of claim 1 wherein the amount of the water and carbondioxide introduced into the injection point in such that when the carbondioxide and water are in solution, the solution is at least as great as10 percent of the pore volume of the reservoir.

14. The method of claim 13 wherein the fluid including a gaseous phasealso includes an aqueous phase.

15. The method of claim 14 wherein the aqueous phase is a carbonatedwater solution.

16. The method of claim 13 wherein before the fluid including thegaseous phase is injected, the bottomhole pressure at the injectionpoint is at least as great as the second miscible pressure.

17. The method of claim 16 wherein the fluid including a gaseous phasealso includes an aqueous phase.

18. The method of claim 17 wherein the aqueous phase is a carbonatedwater solution.

19. The method of claim 16 wherein at least a portion of the gaseousphase is injected at a bottomhole pres sure at least 200 psi higher thanthe highest bottomhole pressure reached during step (a) at saidinjection point.

20. The method of claim 19 wherein the fluid including a gaseous phasealso includes an aqueous phase.

21. The method of claim 20 wherein the aqueous phase is a carbonatedwater solution.

22. The method of claim 13 wherein at least a portion of the gaseousphase is injected at a bottomhole pressure at least 200 psi higher thanthe highest bottomhole pressure reached during step (a) at saidinjection point.

23. The method of claim 22 wherein the fluid including a gaseous phasealso includes an aqueous phase.

24. The method of claim 23 wherein the aqueous phase is a carbonatedwater solution.

2. The method of claim 1 wherein the fluid including a gaseous phasealso includes an aqueous phase.
 3. The method of claim 2 wherein theaqueous phase is a carbonated water solution.
 4. The method of claim 1wherein before the fluid including the gaseous phase is injected, thebottomhole pressure at the injection point is at least as great as thesecond miscible pressure.
 5. The method of claim 4 wherein the fluidincluding a gaseous phase also includes an aqueous phase.
 6. The methodof claim 5 wherein the aqueous phase is a carbonated water solution. 7.The method of claim 4 wherein at least a portion of the gaseous phase isinjected at a bottomhole pressure at least 200 psi higher than thehighest bottomhole pressure reached during step (a) at said injectionpoint.
 8. The method of claim 7 wherein the fluid including a gaseousphase also includes an aqueous phase.
 9. The method of claim 8 whereinthe aqueous phase is a carbonated water solution.
 10. The method ofclaim 1 wherein at least a portion of the gaseous phase is injected at abottomhole pressure at least 200 psi higher than the highest bottomholepressure reached during step (a) at said injection point.
 11. The methodof claim 10 wherein the fluid including a gaseous phase also includes anaqueous phase.
 12. The method of claim 11 wherein the aqueous phase is acarbonated water solution.
 13. The method of claim 1 wherein the amountof the water and carbon dioxide introduced into the injection point insuch that when the carbon dioxide and water are in solution, thesolution is at least as great as 10 percent of the pore volume of thereservoir.
 14. The method of claim 13 wherein the fluid including agaseous phase also includes an aqueous phase.
 15. The method of claim 14wherein the aqueous phase is a carbonated water solution.
 16. The methodof claim 13 wherein before the fluid including the gaseous phase isinjected, the bottomhole pressure at the injection point is at least asgreat as the second miscible pressure.
 17. The method of claim 16wherein the fluid including a gaseous phase also includes an aqueousphase.
 18. The method of claim 17 wherein the aqueous phase is acarbonated water solution.
 19. The method of claim 16 wherein at least aportion of the gaseous phase is injected at a bottomhole pressure atleast 200 psi higher than the highest bottomhole pressure reached duringstep (a) at said injection point.
 20. The method of claim 19 wherein thefluid including a gaseous phase also includes an aqueous phase.
 21. Themethod of claim 20 wherein the aqueous phase is a carbonated watersolution.
 22. The method of claim 13 wherein at least a portion of thegaseous phase is injected at a bottomhole pressure at least 200 psihigher than the highest bottomhole pressure reached during step (a) atsaid injection point.
 23. The method of claim 22 wherein the fluidincluding a gaseous phase also includes an aqueous phase.
 24. The methodof claim 23 wherein the aqueous phase is a carbonated water solution.